WO2012118851A2 - Ensemble de séparation pour éléments cylindriques - Google Patents

Ensemble de séparation pour éléments cylindriques Download PDF

Info

Publication number
WO2012118851A2
WO2012118851A2 PCT/US2012/027011 US2012027011W WO2012118851A2 WO 2012118851 A2 WO2012118851 A2 WO 2012118851A2 US 2012027011 W US2012027011 W US 2012027011W WO 2012118851 A2 WO2012118851 A2 WO 2012118851A2
Authority
WO
WIPO (PCT)
Prior art keywords
serration
disconnect assembly
serrations
sleeve
tubular member
Prior art date
Application number
PCT/US2012/027011
Other languages
English (en)
Other versions
WO2012118851A3 (fr
Inventor
Neil H. Akkerman
John Barton
Original Assignee
Akkerman Neil H
John Barton
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Akkerman Neil H, John Barton filed Critical Akkerman Neil H
Priority to CA2828486A priority Critical patent/CA2828486C/fr
Priority to EP12751793.6A priority patent/EP2681405B1/fr
Publication of WO2012118851A2 publication Critical patent/WO2012118851A2/fr
Publication of WO2012118851A3 publication Critical patent/WO2012118851A3/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/046—Couplings; joints between rod or the like and bit or between rod and rod or the like with ribs, pins, or jaws, and complementary grooves or the like, e.g. bayonet catches
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
    • E21B17/02—Couplings; joints
    • E21B17/04—Couplings; joints between rod or the like and bit or between rod and rod or the like
    • E21B17/06—Releasing-joints, e.g. safety joints

Definitions

  • This disclosure relates to releasable connections between cylindrical members or bodies.
  • this disclosure relates to connections between downhole tubulars, such as drill pipe tool joints, as are employed in the rotary system of drilling. More particularly, the downhole tubular connections or drill pipe tool joints include connections configured to be selectively disconnectable within the well bore, such that upper and lower portions of the downhole tubular string can be separated.
  • a drill bit is attached to the lower end of a drill stem composed of lengths of tubular drill pipe and other components joined together by tool joints with rotary shouldered threaded connections.
  • drill stem is intended to include other forms of downhole tubular strings such as drill strings and work strings.
  • a rotary shouldered threaded connection may also be referred to as a RSTC.
  • the tubular members that make up a drill stem may also be substituted with other rods, shafts, or other cylindrical members that may be used at the surface and which may require a releasable connection.
  • the drill stem may include threads that are engaged by right hand and/or left hand rotation.
  • the threaded connections must sustain the weight of the drill stem, withstand the strain of repeated make-up and break-out, resist fatigue, resist additional make-up during drilling, provide a leak proof seal, and not loosen during normal operations.
  • the rotary drilling process subjects the drill stem to tremendous dynamic tensile stresses, dynamic bending stresses and dynamic rotational stresses that can result in premature drill stem failure due to fatigue.
  • the accepted design of drill stem connections is to incorporate coarse tapered threads and metal to metal sealing shoulders. Proper design is a balance of strength between the internal and external threaded connection. Some of the variables include outside diameter, inside diameters, thread pitch, thread form, sealing shoulder area, metal selection, grease friction factor and assembly torque. Those skilled in the art are aware of the interrelationships of these variables and the severity of the stresses placed on a drill stem.
  • the tool joints or pipe connections in the drill stem must have appropriate shoulder area, thread pitch, shear area and friction to transmit the required drilling torque.
  • all threads in the drill string must be assembled with a torque exceeding the required drilling torque as a minimum, or more to handle tensile and bending loads without shoulder separation because shoulder separation causes leaks and fretting wear.
  • Drill stem and tool joints with rotary shouldered threaded connections are addressed by industry accepted standards such as, but not limited to: International Industry Standard (ISO), ISO 10424-1 :2004 (modified) - Part 1 and Part 2; Petroleum and natural gas industries-Rotary drilling equipment - Part 1 : Rotary drill stem elements; American Petroleum Institute (API), API 7-1 Specification for Rotary Drill Stem Elements; API 7G Recommended Practice for Drill Stem Design and Operating Limits; and others.
  • ISO International Industry Standard
  • ISO 10424-1 2004 (modified) - Part 1 and Part 2
  • Petroleum and natural gas industries-Rotary drilling equipment - Part 1 Rotary drill stem elements
  • API American Petroleum Institute
  • API 7-1 Specification for Rotary Drill Stem Elements API 7G Recommended Practice for Drill Stem Design and Operating Limits
  • These standards address design, manufacture, use and maintenance of drill stem thread joints.
  • Offshore drilling for example, is performed in progressively deeper water, with deeper penetration of the earth and possibly having higher deviations from a vertical bore hole.
  • many wells now have sections of horizontal bore hole. The temperatures are high, the friction between drill stem and borehole is high, the hanging weight is extreme and the well bores may not be straight. Consequently, a portion of the drill stem often becomes stuck at a great distance from the surface, preventing its movement and recovery. Further causes of stuck drill pipe include accumulation of cuttings falling out of circulated fluids, unconsolidated earth caving in the borehole, low pressure strata capturing the drill stem due to differential pressure, and the like.
  • the first remedial action is to identify the point at which the drill stem is stuck. A decision is then often made to either explosively loosen a thread joint or sever the drill stem with highly reactive explosive or chemical tools.
  • tubing disconnects designed for within-the- well-bore activation are lacking.
  • tubing disconnects are disposed in work strings or pipe strings used for coiled tubing drilling, well completion, workover, and other services less demanding than rotary drilling. Consequently, current tubing disconnects do not meet the requirements of the ISO and/or API specifications for rotary drilling equipment. They incorporate non- shouldered connections and/or connections that do not establish a stress pattern within the connection to prevent shoulders from separation under extreme tension and/or bending loads.
  • tubing disconnects employ non-metal seals. Failure of one of these seals may result in a washout or total joint failure.
  • the sliding fit of the seals facilitates fretting and wear as the tubing is flexed in response to axial, bending and rotational forces.
  • Some tubing disconnects make use of springs or washers that restrict the inside diameter of the tubing string, or leave a connection in the well that cannot be easily reconnected without special tools.
  • Some tubing disconnects leave a ball or other activation device in the well that can inhibit additional work that may be required after recovery of the upper unstuck tubing section.
  • tubing disconnects are intended for very specific applications. Often, the environment in which these tubing disconnects are operated is relatively stable and predictable. For example, such tubing disconnects are intended for releasing perforating guns after firing, sub-sea risers, or coiled tubing drilling bits. However, such tubing disconnects do not have the ruggedness and are not designed to operate in the extremes of rotary drilling. Such tubing disconnects often include mechanical features that a driller would recognize as a weak link in a rotary drill stem.
  • Some current tubing disconnects include pressure activation, requiring the ability to circulate fluids within the well tubing.
  • Pressure activated tubing disconnects are typically activated by dropping or pumping a ball or like device to engage a seat, so that pressure may be applied down the tubing to initiate disconnection. Without circulation, differential pressure cannot be reliably established to disconnect the tubing.
  • the seat is a restriction to and subject to damage by the passage of instruments such as measurement while drilling tools and the like. Accidental impact of tools passing the seat may initiate inadvertent and unwanted disconnection. If the well tubing is plugged, a circulation port must be opened before disconnection is possible. A circulation port degrades the reliability and pressure integrity of the tubing.
  • a drill bit and drill stem may drill a significant distance into the earth without requiring removal and refitting of a new drill bit. It is problematic to determine where to install a disconnect within the drill stem. Deciding the optimum location of a disconnect requires an accurate estimation of the probable depth of the portion of the drill stem that has become stuck. This problem is compounded because a disconnect is lowered progressively deeper as the well is drilled. The tubing or drill stem may become stuck due to solids, such as sand, falling out of well fluid suspension at any depth within a well.
  • a downhole tubular string disconnect mechanism in accordance with the principles disclosed herein may be configured for selective activation within the well bore, meet industry standards and/or expectations of ruggedness for rotary drilling and other downhole applications, be insensitive to the passage of instruments and tools, not require well fluid circulation, not require pressure application to the drill stem, not leave an obstructed well bore after disconnection, and allow disconnection of a drill stem at selectable, multiple locations by installing multiple disconnects along the length of the drill stem and providing the ability to disconnect the lowest one in the unstuck portion of the drill stem.
  • Other limitations are also overcome, including for cylindrical member couplings such as for drive shafts.
  • up, upper, upward or upwardly refer to a direction, portion, motion or action that is closer to the surface of the earth and/or closer to the surface of the water and/or that which is further from the bottom of the well.
  • the words down, lower, downward or downwardly refer to a direction, portion, motion or action that is further from the surface of the earth and/or further from the surface of the water and/or that which is closer to the bottom of the well.
  • RSTC Rotary shouldered threaded connection
  • Tool joint is a heavy coupling element utilizing a rotary shouldered connection.
  • a tool joint in a drill stem typically has coarse tapered threads and sealing shoulders designed to sustain the weight of the drill stem, withstand the strain of repeated make-up and breakout, resist fatigue, resist additional make up during drilling and provide a leak proof seal.
  • API specifications include a series of numbered tool joint designs; however, proprietary tool joint designs exist that are different from the numbered tool joints of API that include rotary shouldered connections.
  • Drill stem is an assembly of components joined by tool joints for use in a well for rotary drilling. Components such as a drill bit, a bit sub, drill collars, crossover subs, drill pipe, kelley valves, a swivel sub, a swivel and the like are included.
  • Drill string is a length of connected drill pipes used for drilling. As previously described, “tubing” refers to those conveyances used for coiled tubing drilling, well completion, workover, and other services less demanding than rotary drilling.
  • tubular member or “tubular string” refer to all of the various pipes and strings mentioned above regardless of their specific application in the well.
  • Minimum make-up torque is the minimum amount of torque necessary to develop an arbitrary derived tensile stress in the external thread or compressive stress in the internal thread of a tool joint. This arbitrary derived stress level is perceived as being sufficient in most conditions to prevent downhole make-up and to prevent shoulder separation from bending loads.
  • “Friction factor” is a value that represents the coefficient of friction of mating surfaces within a threaded connection and the relative magnitude of assembly torque required to achieve a recommended stress level in an assembled connection, as specified by the API.
  • Torque turn is a technique of recording assembly torque and rotation as a thread connection is assembled or disassembled.
  • the collected data is usually analyzed on a computer with specialized software.
  • Washout is a portion of borehole enlarged by erosion of high velocity fluid flow or leakage.
  • an assembly for disconnecting and removing an upper portion of a drill stem or tubular string from a well is represented by the various embodiments herein.
  • the drill stem or tubular string may become stuck in the well, and the disconnect assembly may be used to separate an upper portion of the drill stem from a lower, stuck portion of the drill stem.
  • the disconnect assembly (also referred to as a drill stem disconnect or DSD) comprises an upper body and a lower body connected by a rotary shouldered threaded connection (RSTC), wherein the assembly is adapted to be installed as part of a rotary drill stem.
  • RSTC rotary shouldered threaded connection
  • the drill stem may be other various kinds of tubular strings
  • the RSTC may be other kinds of joints such as non-shouldered joints and joints not meeting specific API standards, without affecting the principles disclosed herein.
  • the RSTC may be configured to assemble at a lower torque than other connections within the drill stem and meet the requirements of accepted drilling industry standards.
  • the RSTC may be configured to assemble with rotation in either direction.
  • the DSD may be configured to withstand the fatigue caused by dynamic tensile, compressive and rotational loads experienced within a rotary drill stem.
  • the upper and lower bodies when in a locked position, may be blocked from relative rotation by a third body engaging the upper and lower bodies after proper torque has been applied, thereby assuring retention of proper assembly torque and allowing the transmission of torque equal to the other connections of the drill stem.
  • the third body may be locked in place and may be selectively released and moved from blocking engagement of the upper and lower bodies.
  • An activation tool may selectively unlock and move the third body out of blocking engagement with at least one of the upper or lower bodies, to allow rotation for disengaging the upper and lower bodies.
  • the tool may be powered by hydrostatic pressure within the well bore. Circulation of well fluids may not be required and pressure need not be applied to the well.
  • An embodiment of the tool may include a selective anchor allowing any one of multiple identical drill stem disconnects installed in the drill stem to be unlocked and unblocked.
  • the UUT may be configured such that it is retained and removed with the upper body and the upper disconnected portion of the drill stem. After removal of the upper disconnected portion of the drill stem, the upward facing connection of the lower body, remaining in the well, is unobstructed, facilitating reattachment of a later deployed string or tool.
  • a drill stem tool joint depends on proper assembly torque to achieve optimum performance. If all tool joints in a drill stem similarly configured, then they are typically assembled with the same torque. If the tool joints within a drill stem vary in size, proprietary design, material properties and the like, then they must be assembled with a minimum make up torque value that exceeds the torque value required to be transmitted during drilling operations. If a joint cannot withstand this level of assembly or make up torque, then the joints are sometimes bonded using epoxy compounds. Assembly torque may need to be greater and vary along the length of drill stem to prevent tensile and bending loads from separating the rotary shoulders within a tool joint.
  • the torque required to disassemble a particular tool joint is a function of assembly torque. More assembly torque results in more disassembly torque necessitated to disassemble the tool joint. Furthermore, tool joints may tighten when in use because of jarring and/or impact of the working drill bit, temperature effects on thread lubricants, and time of use.
  • An example of this concept is to assemble identical tool joints with lubricants of different friction factors, the high torque tool joints assembled with high friction factor grease and the low assembly torque joints assembled with low friction factor grease and subsequently disposed to be rotationally blocked from further assembly or disassembly.
  • a tool joint assembled with low torque and not rotationally blocked will disassemble with low torque.
  • a stuck drill string will disassemble, through reverse rotation of the upper un-stuck drill string, at an unblocked low assembly torque tool joint location.
  • a rotationally blocked, low assembly torque tool joint that facilitates selective, within-the-well-bore un-blocking, can facilitate the removal of the upper unstuck drill stem and yet satisfy industry standards, such as API 7G, when rotationally blocked.
  • a disconnect assembly includes an upper body and a lower body connected by a rotary shouldered threaded connection, adapted to be installed as part of a rotary drill stem.
  • the rotary shouldered threaded connection is adapted to assemble at a lower torque than other connections within the drill stem and meet the requirements of accepted drilling industry standards.
  • the rotary shouldered threaded connection may be configured to assemble with rotation in either direction.
  • the assembly is designed to withstand the fatigue caused by dynamic tensile, compressive and rotational loads experienced within a rotary drill stem.
  • the upper and lower bodies are blocked from further rotation by a third body, or rotational blocking sleeve, engaging the upper and lower bodies after proper torque has been applied, thereby assuring retention of proper assembly torque and allowing the transmission of torque equal to the other connections of the drill stem.
  • the third body is locked in place and may be selectively released and moved from blocking engagement.
  • a locking assembly has a bore larger than surrounding bores and is thus protected from accidental engagement when well bore instruments or tools are passed therethrough.
  • the rotational blocking sleeve or member provides accurate rotational positioning between the upper and lower bodies for proper torque retention.
  • the blocking sleeve accommodates variations of angular alignment when the upper and lower bodies are properly assembled.
  • the blocking member is a serrated or splined blocking sleeve that facilitates selective blocking and unblocking of the upper and lower bodies, wherein the upper and lower bodies are joined by a low assembly torque rotary shouldered threaded connection.
  • the blocking sleeve is moveable to and from blocking engagement with the upper and lower bodies using a sliding fit including a small amount of angular clearance.
  • the splines or first serration of the upper body include a different number of teeth, or a different angular pitch, than the splines or second serration of the lower body.
  • the blocking sleeve includes accommodating or mating splines or serrations.
  • the blocking sleeve serrations have a progressive, incremental angle between the individual features or teeth forming the serrations because of the differing number of teeth or angular pitch.
  • the incremental pitch between upper and lower serrations on the blocking sleeve is smaller than the total of the angular clearance between the upper body serration and the upper serration of the blocking sleeve plus the angular clearance between the lower body serration and the lower serration of the blocking sleeve.
  • the blocking sleeve has a 50-tooth serration on one axial end and a 51 -tooth serration on the other axial end, the incremental angle will be
  • the blocking sleeve may be installed for any angular orientation of the upper and lower splines and the maximum angular deviation from nominal is 0.2 degrees. It is noted that other angular clearances, both less than and greater than 0.2 degrees can be used.
  • the compressive stress retained in the rotationally blocked rotary shouldered connection of the assembly embodiments described herein is retained between a minimum and maximum allowed value. So when configured, the upper and lower bodies or subs of the disconnect assembly disclosed herein may be torqued to a specific or predetermined value and, without rotational adjustment, the blocking sleeve may be engaged.
  • the blocking sleeve is retained in the engaged position by a locking mechanism that transfers impact and vibration forces directly from the blocking sleeve to the upper and lower bodies of the assembly.
  • the locking mechanism is held and selectively released in response to forces applied by the unlocking and unblocking tool disclosed herein.
  • an unlocking and unblocking tool selectively unlocks and moves the sleeve out of blocking engagement between the upper or lower bodies, to allow rotation to disengage the upper and lower bodies of the drill stem disconnect assembly.
  • the UUT is powered by hydrostatic pressure within the well bore. Circulation of well fluids is not required and pressure need not be applied to the well.
  • the UUT includes a selective anchor allowing any one of multiple identical drill stem disconnects installed in the drill stem to be unlocked and unblocked.
  • the activating UUT is configured such that it is retained and removed with the upper body and the upper disconnected portion of the drill stem. After removal of the upper disconnected portion of the drill stem, the upward connection of the lower body, remaining in the well, is unobstructed, facilitating re-attachment.
  • a disconnect assembly includes a first body including a first serration, a second body including a second serration, and a third body including a third serration to be engaged with the first serration using a first number of teeth, and the third body include a fourth serration to be engaged with the second serration using a second number of teeth to lock the first body relative to the second body.
  • the third body is free to rotate to align the first and third serrations and the second and further serrations prior to movement of the third body to a locking position.
  • a disconnect assembly includes a first tubular member including a first inner serration, a second tubular member including a second inner serration, wherein the first tubular member is coupled to the second tubular member, and an inner sleeve including an upper serration engaged with the first inner serration with a first angular pitch, and a lower serration engaged with the second inner serration with a second angular pitch.
  • the upper serration and the first inner serration each have the same number of teeth
  • the lower serration and the second inner serration each have the same number of teeth that is different than the number of upper serration teeth.
  • the engaged upper serration and first inner serration has a first clearance
  • the engaged lower serration and second inner serration has a second clearance
  • the upper and lower serrations have an incremental pitch less than the sum of the first and second clearances.
  • a disconnect assembly includes a first tubular member including a first inner serration, a second tubular member including a second inner serration, an inner sleeve including an upper serration engaged with the first inner serration and a lower serration engaged with the second inner serration, and a rotary shouldered and threaded connection coupling the first and second tubular members.
  • the upper and lower serrations are axially engageable with the first and second serrations for any rotational position of the inner sleeve using a first angular pitch for the upper engaged serration and a second angular pitch for the lower engaged serration.
  • a disconnect assembly includes a first tubular member including a first inner spline, a second tubular member including a second inner spline, and an inner sleeve including an upper spline engaged with the first inner spline and a lower spline engaged with the second inner spline, wherein the inner sleeve is held into engagement with the first and second tubular members by a lock.
  • a disconnect assembly for a downhole tubular string includes a first body connected to a second body with a threaded connection, a first serration in the first body, a second serration in the second body, a third body including upper and lower serrations for mating engagement with the first and second serrations, the third body, in a first position, prevents rotation between the first and second bodies, and in a second position allows relative rotation between the first and second bodies, and the upper and lower serrations are aligned with the first and second serrations for movement of the third body between the first and second positions after an assembly torque is applied to develop a predetermined amount of axial load between the first and second bodies.
  • the third body is free to rotate between the first and second positions to align the upper and lower serrations with the first and second serrations for movement of the third body into a locking position.
  • FIG. 1 is an end view defining section views FIG. 2A, 2B, 2E, and 2F; [0051] FIG. 2A is a section view of the upper most end of the DSD;
  • FIG. 2B is an intermediate section view of the DSD
  • FIG. 2C is an intermediate section view of the DSD
  • FIG. 2D is an intermediate section view of the DSD
  • FIG. 2E is an intermediate section view of the DSD
  • FIG. 2F is a section view of the lower most end of the DSD
  • FIG. 3 is a section view, shown in full, defined in FIG. 2C;
  • FIG. 4 is a section view, shown in full, defined in FIG. 2C
  • FIG. 5 is a section view, shown in full, defined in FIG. 2C
  • FIG. 6 is a section view, shown in full, defined in FIG. 2D
  • FIG. 7 is a section view, shown in full, defined in FIG. 2D
  • FIG. 8 is a section view, shown in full, defined in FIG. 2D;
  • FIG. 9 is an end view defining section views FIG. 10A, 10B, and 10F;
  • FIG. 10A is a section view of the upper most end an alternate construction DSD
  • FIG. 10B is an intermediate section view of the alternate construction DSD
  • FIG. IOC is an intermediate section view of the alternate construction DSD
  • FIG. 10D is an intermediate section view of the alternate construction DSD
  • FIG. 10E is an intermediate section view of the alternate construction DSD
  • FIG. 10F is a section view of the lower most end of the alternate construction DSD
  • FIG. 11 is a section view, shown in full, defined in FIG. 10A;
  • FIG. 12 is a section view, shown in full defined in FIG. 10B;
  • FIG. 13 is a section view, shown in full defined in FIG. IOC;
  • FIG. 14 is a section view, shown in full defined in FIG. IOC;
  • FIG. 15 is a section view, shown in full defined in FIG. IOC;
  • FIG. 16 is a section view, shown in full defined in FIG. 10D;
  • FIG. 17 is a section view, shown in full defined in FIG. 10D;
  • FIG. 18 is a section view, shown in full defined in FIG. 10D;
  • FIG. 19 is a section view, shown in full defined in FIG. 10D;
  • FIG. 20 is a section view, shown in full defined in FIG. 10D;
  • FIG. 21 is a section view, shown in full defined in FIG. 10E;
  • FIG. 22 is a side view of a blocking sleeve
  • FIG. 22 A is an end view, defined in FIG. 22;
  • FIG. 22B is a section view, defined in FIG. 22;
  • FIG. 22C is a section view, defined in FIG. 22; [0085] FIG. 22D is a detail view, defined in FIG. 22A;
  • FIG. 23 is a side view of an alternate blocking sleeve
  • FIG. 23 A is an end view defined in FIG. 23;
  • FIG. 23B is a section view, defined in FIG. 23;
  • FIG. 23C is a section view, defined in FIG. 23;
  • FIG. 23D is a detail view defined in FIG. 23A;
  • FIG. 24 not used
  • FIG. 25A is a section view of the upper most end of the UUT
  • FIG. 25B is an intermediate section view of the UUT
  • FIG. 25C is an intermediate section view of the UUT
  • FIG. 25D is an intermediate section view of the UUT
  • FIG. 25E is an intermediate section view of the UUT
  • FIG. 25F is an intermediate section view of the UUT
  • FIG. 25G is an intermediate section view of the UUT
  • FIG. 25H is a section view of the lower most end of the UUT.
  • FIG. 26 is a section view, shown in full, defined in FIG. 25A;
  • FIG. 27 is a section view, shown in full, defined in FIG. 25A;
  • FIG. 28 is a section view, shown in full, defined in FIG. 25A;
  • FIG. 29 is a section view, shown in full, defined in FIG. 25B;
  • FIG. 30 is a section view, shown in full, defined in FIG. 25B;
  • FIG. 31 is a section view, shown in full, defined in FIG. 25B;
  • FIG. 32 is a section view, shown in full, defined in FIG. 25B;
  • FIG. 33 is a section view, shown in full, defined in FIG. 25C;
  • FIG. 34 is a section view, shown in full, defined in FIG. 25D;
  • FIG. 35 is a section view, shown in full, defined in FIG. 25E;
  • FIG. 36 is a section view, shown in full, defined in FIG. 25E;
  • FIG. 37 is a section view, shown in full, defined in FIG. 25E;
  • FIG. 38 is a section view, shown in full, defined in FIG. 25E;
  • FIG. 39 is a section view, shown in full, defined in FIG. 25E;
  • FIG. 40 is a section view, shown in full, defined in FIG. 25F;
  • FIG. 41 is a section view, shown in full, defined in FIG. 25F;
  • FIG. 42 is a section view, shown in full, defined in FIG. 25F;
  • FIG. 43 is a section view, shown in full, defined in FIG. 25F;
  • FIG. 44 is a section view, shown in full, defined in FIG. 25G;
  • FIG. 45 is a section view, shown in full, defined in FIG. 25G;
  • FIG. 46 is a section view, shown in full, defined in FIG. 25G;
  • FIG. 47A is a partial section view of the UUT as shown in FIG. 25A and FIG. 25B; as it is lowered through a drill stem above the DSD as shown in FIG. 2A and FIG. 2B;
  • FIG. 47B is a partial section view of the UUT as shown in FIG. 25A and FIG. 5B; as it is lowered within the DSD as shown in FIG. 2B and FIG. 2C;
  • FIG. 47C is a partial section view of the UUT as shown in FIG. 25A and FIG. 5B; as it is lowered further within the DSD as shown in FIG. 2B and FIG. 2C;
  • FIG. 47D is a partial section view of the UUT as shown in FIG. 25A and FIG. 25B; as it is lifted within the DSD from below as shown in FIG. 2B and FIG. 2C;
  • FIG. 47E is a partial section view of the UUT as shown in FIG. 25A and FIG. 25B; as it is lifted further within the DSD from below as shown in FIG. 2B and FIG. 2C;
  • FIG. 47F is a partial section view of the UUT as shown in FIG. 25A and FIG. 25B; as it is lifted even further within the DSD from below as shown in FIG. 2A and FIG. 2B;
  • FIG. 47G is a partial section view of the UUT as shown in FIG. 25A and FIG. 25B; after landing in the DSD as shown in FIG. 2A and FIG. 2B;
  • FIG. 48A is a section view of the upper most end of the UUT landed in the DSD;
  • FIG. 48B is an intermediate section view of the UUT landed in the DSD
  • FIG. 48C is an intermediate section view of the UUT landed in the DSD
  • FIG. 48D is an intermediate section view of the UUT landed in the DSD
  • FIG. 48E is a section view of the lower most end of UUT landed in the DSD
  • FIG. 49A is a section view of the upper most end of the UUT landed in the DSD;
  • FIG. 49B is an intermediate section view of the UUT locked in the DSD
  • FIG. 49C is an intermediate section view of the UUT locked in the DSD
  • FIG. 49D is an intermediate section view of the UUT locked in the DSD
  • FIG. 49E is a section view of the lower most end of UUT locked in the DSD.
  • FIG. 50A is a section view of the upper most end of the UUT activated, the DSD unlocked and unblocking initiated;
  • FIG. 50B is an intermediate section view of the UUT activated, the DSD unlocked and unblocking initiated;
  • FIG. 50C is an intermediate section view of the UUT activated, the DSD unlocked and unblocking initiated;
  • FIG. 50D is an intermediate section view of the UUT activated, the DSD unlocked and unblocking initiated;
  • FIG. 50E is a section view of the lower most end of UUT activated, the DSD unlocked and unblocking initiated;
  • FIG. 51A is a section view of the upper most end of the UUT, the locking sleeve released and the blocking sleeve further moved;
  • FIG. 51B is an intermediate section view of the UUT, the locking sleeve released and the blocking sleeve further moved;
  • FIG. 51C is an intermediate section view of the UUT, the locking sleeve released and the blocking sleeve further moved;
  • FIG. 51D is an intermediate section view of the UUT, the locking sleeve released and the blocking sleeve further moved;
  • FIG. 51E is a section view of the lower most end of UUT, the locking sleeve released and the blocking sleeve further moved;
  • FIG. 52A is a section view of the upper most end of the UUT, the blocking sleeve fully moved and released;
  • FIG. 52B is an intermediate section view of the UUT, the blocking sleeve fully moved and released;
  • FIG. 52C is an intermediate section view of the UUT, the blocking sleeve fully moved and released;
  • FIG. 52D is an intermediate section view of the UUT, the blocking sleeve fully moved and released;
  • FIG. 52E is a section view of the lower most end of UUT, the blocking sleeve fully moved and released;
  • FIG. 53A is a section view of the upper most end of the UUT, the blocking sleeve released, the tool extended and pressures equalized;
  • FIG. 53B is an intermediate section view of the UUT, the blocking sleeve released, the tool extended and pressures equalized;
  • FIG. 53C is an intermediate section view of the UUT, the blocking sleeve released, the tool extended and pressures equalized;
  • FIG. 53D is an intermediate section view of the UUT, the blocking sleeve released, the tool extended and pressures equalized;
  • FIG. 53E is a section view of the lower most end of UUT, the blocking sleeve released, the tool extended and pressures equalized;
  • FIG. 54A is a section view of the upper most end of the UUT, the drill stem disconnected and the unblocking and unblocking tool being lifted from the well bore;
  • FIG. 54B is an intermediate section view of the UUT, the drill stem disconnected and the unblocking and unblocking tool being lifted from the well bore;
  • FIG. 54C is an intermediate section view of the UUT, the drill stem disconnected and the unblocking and unblocking tool being lifted from the well bore;
  • FIG. 54D is an intermediate section view of the UUT, the drill stem disconnected and the unblocking and unblocking tool being lifted from the well bore;
  • FIG. 54E is a section view of the lower most end of UUT, the drill stem disconnected and the unblocking and unblocking tool being lifted from the well bore;
  • FIGS. 55-71 are similar sections view as above showing multiple alternative embodiments of both the DSD and the UUT.
  • FIGS. 72-88 are elevation and section views of alternative embodiments of a disconnect assembly in accordance with the principles of this disclosure.
  • the drill stem disconnect assembly 50 includes a generally tubular shape with an outer surface
  • An upper body or sub 1 is connected to a lower body or sub 2 (FIG. 2C) by a tool joint
  • Tool joint 15 is a heavy coupling element utilizing a rotary shouldered and threaded connection.
  • upper body 1 includes an internal upper thread lc, often called a female thread or a box thread, which is half of a tool joint for connection within a drill stem.
  • the axial lower end of lower body 2 (FIG. 2F) includes an external lower thread 2c, often called a male thread or pin thread, which is the other half of a tool joint for connection within a drill stem.
  • upper body 1 has an upper shoulder If (FIG. 2A) displaced from lower shoulder lb (FIG. 2B) by an internal recess lh which is axially above internal diameter la; forming landing profile 11.
  • internal diameter la is smaller than tool joint internal diameter lk (FIG. 2A), internal diameter of the passage of the drill stem above upper body 1, internal diameter 3a (FIG. 2C) of blocking sleeve 3, internal diameter 2g of lower body 2 and the internal diameter of the passage of the drill stem below lower body 2.
  • Tool joint 15 may be designed or specially lubricated such that it is properly assembled at a lower torque than other tool joints in a drill stem.
  • Upper thread lc (FIG. 2A) and lower thread 2c (FIG. 2F) are part of tool joints and form tool joints of a drill stem (not shown). These tool joints and others of the drill stem may be designed or lubricated to properly assemble at a higher assembly torque than that required to assemble tool joint 15.
  • Serration or splines Id within upper body 1 and serrations or splines 2d (FIGS. 2C and 5) within lower body 2 may be formed in different manners such as, but not limited to, milling, shaping, electro discharge machining and the like.
  • Internal diameter la is smaller than serration Id
  • internal diameter 2g is smaller than serration 2d; it may be practical to form serration Id and serration 2d in upper body 1, while forming lower body 2 individually when not assembled at tool joint 15.
  • alignment of serration Id and serration 2d when tool joint 15 is properly assembled may vary because of manufacturing tolerances, wear, thickness of lubrication and the like.
  • blocking sleeve 3 (FIG. 2C) is disposed radially within upper body 1 and lower body 2.
  • Blocking sleeve 3 has upper serration or splines 3b radially engaged with compatible or mating serration Id of upper body 1 and lower serration or splines 3c (FIG. 2C) engaged with compatible or mating serration 2d of lower body 2.
  • Upper serration 3b of blocking sleeve 3 and serration Id of upper body 1 are complementary and have angular clearance 13 (FIG. 3) configured for sliding engagement; accordingly, they may have the same number or angular pitch serration.
  • Lower serration 3c of blocking sleeve 3 and serration 2d of lower body 2 are complementary and have angular clearance 13a (FIG. 5) configured for sliding engagement; accordingly, they may have the same number or angular pitch serration.
  • Upper serration 3b of blocking sleeve 3 and serration Id of upper body 1 have a different number or angular pitch than lower serration 3c of blocking sleeve 3 and serration 2d of lower body 2.
  • Angular clearance 13 (FIG. 3) added with angular clearance 13a (FIG. 5) results in a clearance that is greater than incremental pitch 14 (FIG. 22D) between lower serration 3c and upper serration 3b.
  • FIGS. 22 and 22A-22D the incremental pitch 14 (FIG. 22D) between serration 3b and serration 3c of blocking sleeve 3 is shown adjacent to aligned set of teeth 14a (though alignment is not necessary for the pitch increment).
  • FIGS. 22C and 22B illustrate serration 3c and serration 3b respectively, while FIG. 22A illustrates both serration 3b and serration 3c as viewed from the axial end of FIG. 22.
  • serration 3b includes 50 teeth while serration 3c includes 51 teeth.
  • Serration 3b and serration 3c include a set of aligned teeth 14a. Due to the difference in the number of teeth between serration 3b and serration 3c, the set of teeth 14b (FIG.
  • circumferentially adjacent to aligned set 14a are not angularly aligned like the aligned set of teeth 14a, but instead are out of phase by the amount of incremental pitch 14. Additional sets of teeth along the circumference of serrations 3b and 3c will be further out of phase, with the next additional set circumferentially adjacent to set 14b out of phase by twice the incremental pitch, the next circumferentially adjacent set out of phase by triple the incremental pitch, etc., until serration 13b and serration 13c are completely out of phase at a point along the circumference of serrations 3b and 3c diametrically opposed to aligned set of teeth 14a.
  • serration Id includes 50 teeth (matching serration 3b) and serration 2d (FIG. 5) of lower body 2 includes 51 teeth (matching serration 3c), mirroring the incremental pitch 14a of serration 3b and 3c of blocking sleeve 3.
  • serration Id and serration 2d will include sets of teeth in phase and sets of teeth incrementally out of phase, with the incremental shift into and out of phase by each set of teeth governed by the incremental pitch.
  • aligning the in phase sets of teeth of serrations 3b and 3c with the corresponding in phase sets of teeth of serrations Id and 2d allows upper serration 3b to engage serration Id simultaneously with the engagement between lower serration 3c and serration 2d, regardless of the rotational alignment of serration Id and serration 2d when tool joint 15 is properly assembled.
  • Blocking sleeve 3 so engaged, prevents relative rotation between upper body 1 and lower body 2.
  • blocking sleeve 3 includes an upper seal surface 3e, lower seal surface 3f, intermediate gap 3d, internal diameter 3a, upper end 3g of upper serration 3b, lower end 3h of lower serration 3c, upper end 3j, and lower end 3i.
  • Blocking sleeve 3 may be prevented from axial upward movement by engagement between upper end 3j of blocking sleeve 3 and shoulder le of upper body 1.
  • Blocking sleeve 3 is prevented from being displaced axially lower by lower end 3i engaging "c" ring 5, which may be disposed axially below blocking sleeve 3.
  • Tool joint 15 is sealed by the contact of the rotary shoulders incorporated therein, while upper seal 10 within groove lm and lower seal 12 within groove 2j function as debris barriers and maintain lubrication of serrations Id, 3b, 2d and 3c.
  • Upper seal surface 3e may be the same or very nearly the same diameter as lower seal surface 3f to assure ease of movement in a high hydrostatic pressure fluid environment.
  • Lock sleeve 4 is lighter than blocking sleeve 3 and thus will create proportionately smaller inertial forces when subjected to the forces of rotary drilling.
  • Shock absorber 6 protects retaining ring 8 from the affects of vibration and impact shock that take place during rotary drilling.
  • Axial gap 16 between "c" ring 5 and the axial upper end of lock sleeve 4 assures that forces acting to move blocking sleeve 3 downward are transferred from blocking sleeve 3, through "c" ring 5, to the shoulder 2b of groove 2a of lower body 2.
  • Internal diameter 3a of blocking sleeve 3 may be smaller than internal diameter 4a of lock sleeve 4, thereby providing protection from forces associated with lowering service tools through the drill stem, such as measurement while drilling tools and the like.
  • Internal diameter 3a may be larger than internal diameter la, which may provide clearance to internal surfaces during the functioning of a UUT, which will be addressed during the discussion of the operation of the assembly below.
  • blocking sleeve 3 may be unlocked by displacing lock sleeve 4 axially downward.
  • a UUT engages shoulder 4b of lock sleeve 4, forcibly compelling shoulder 4d to axially compress shock absorber 6 and force ring 7 to shear retaining ring 8.
  • the UUT displaces lock sleeve 4 downwardly into a position where support surface 4c is no longer in position to axially support "c" ring 5 in the radially expanded position within groove 2a of lower body 2.
  • Blocking sleeve 3 is prevented from further downward displacement when lower end 3i of blocking sleeve 3, acting through "c" ring 5, lock sleeve 4, shoulder 4d, shock absorber 6, ring 7 and inner portion 8b, engages shoulder 2f of lower body 2.
  • Torque applied in the opposite rotational direction from torque applied during assembly will cause rotation between upper body 1 and lower body 2, assuming the portion of drill stem below lower body 2 is stabilized, such as by being stuck in the well bore, and thus will be prevented from rotation in either direction. Continued rotation in the rotational direction opposite of that used in the assembly of tool joint 15 and lifting of the upper unstuck drill stem will disconnect the drill stem at tool joint 15.
  • Filler ring 9 may aid in assembly. Initially filler ring 9 is disposed within bore 2i (FIG. 2E). Retaining ring 8, ring 7, shock absorber 6, lock sleeve 4, "c" ring 5 and blocking sleeve 3 are displaced downward by a UUT until retaining ring 8 engages shoulder 2f of lower body 2. In this configuration, lower serration 3c of blocking sleeve 3 and serration 2d of lower body 2 are disengaged and upper body 1 may be properly assembled to lower body 2.
  • blocking sleeve 3 may be rotated for spline engagement, as discussed more fully above, and displaced upwardly until upper end 3j engages shoulder le of upper body 1. Subsequently, "c" ring 5, forcibly compelled by lock sleeve 4, is displaced upwardly and when it reaches groove 2a (FIG. 2D) "c" ring 5 radially expands and allows lock sleeve 4 to pass underneath "c" ring 5 and radially support "c” ring 5 with support surface 4c. Thereafter, filler ring 9 is displaced axially upward to engage shock absorber 6 and retaining ring 8 with shoulder 4d of lock sleeve 4. In this position, filler "c” ring 9 may radially expand and engage shoulder 2f of lower body 2.
  • Filler "c" ring 9 includes hole 9a and hole 9b to facilitate removal of filler "c” ring 9 from the recess within lower body 2 disposed immediately above shoulder 2f.
  • “c” ring 5 includes hole 5a and hole 5b to facilitate removal of "c” ring 5 from lower body 2.
  • “C” ring 11 has hole 11a and hole lib for the same purpose.
  • Alternative embodiments of a drill stem disconnect assembly including a blocking sleeve are illustrated with reference to FIGS. 9, 10A-10F, 11-21, 23, and 23A-23D. The alternative embodiments described below include some differences from the embodiments described above with reference to FIGS. 1, 2A-2F, 3-8, 22, and 22A-22D.
  • internal diameters 18b, 18e, 18f and 18g and internal diameters 27g are sufficiently diametrically large to allow the forming of serration 18a (FIG. IOC) and serration 27d by displacing a broach with progressively larger teeth axially through an upper sub 18 (FIG. 10B) and a lower sub 27 (FIG. IOC).
  • Serration 18a disposed within upper sub 18 and serration 27d disposed within lower sub 27 may be formed in different manners such as, but not limited to, broaching, milling, shaping, electro discharge machining and the like.
  • An upper body 17 (FIG. 10A) may be assembled as a sub-assembly.
  • Upper body 17 includes: upper sub 18 with ring 24 (FIG. IOC) positioned against shoulder 18d, spacer 22 trapped axially by "c" ring 19 (FIG. 19) , and bushing 20 with a seal 25 that seals between bushing 20 and upper sub 18, with the bushing 20 trapped axially between "c" ring 19 and "c” ring 21 (FIG. 10A).
  • these components forming upper body 17 may be interchangeable with upper body 1 of FIGS. 2A and 2B.
  • a lower body 26 (FIG. 10E) may also be assembled as a sub-assembly.
  • Lower sub 27 includes: "c" ring 45 disposed within groove 27j, removable shoulder 29 (FIG. 10D) including first arc piece 29a, short arc piece 29b and second arc piece 29c, installed in groove 271, removable shoulder 28 (FIG. 17) including first arc piece 28a (FIG. 18), short arc piece 28b and second arc piece 28c, installed in groove 27k (FIG. 10D), collectively form lower body 26, which may be interchangeable with lower body 2 of FIGS. 2C -2F.
  • Tool joint 33 may be a rotary shouldered and threaded connection.
  • Upper sub 18 is shown to have an internal upper thread 18c (FIG. 10A) often called a female thread or a box thread, which is half of a tool joint for connection within a drill stem (not shown).
  • the lower end of lower sub 27 is shown to have an external lower thread 27c (FIG. 10F) often called male thread or pin thread, which is the other half of a tool joint for connection within a drill stem (not shown).
  • FIGS. IOC and 10D blocking sleeve 41 (FIG. IOC) is disposed within upper sub 18 and lower sub 27.
  • Blocking sleeve 41 includes upper serration 41b engaged with compatible or mating serration 18a of upper sub 18 and lower serration 41c engaged with compatible or mating serration 27d of lower sub 27.
  • Upper serration 18a and serration 41b are complementary and have angular clearance 42 (FIG. 13) for sliding engagement; accordingly, upper serration 18a and serration 41b may have the same number or angular pitch serration.
  • Lower serration 41c and serration 27d are complementary and have angular clearance 42a (FIG. 15) for sliding engagement; accordingly, lower serration 41c and serration 27d may have the same number or angular pitch serration.
  • Upper serration 41b and serration 18a of upper sub 18 have a different number or angular pitch than lower serration 41c and serration 27d of lower sub 27.
  • the summation of angular clearance 42 (FIG. 13) and angular clearance 42a (FIG. 15) is greater than the incremental pitch 43 (FIG. 23D) between lower serration 41c and upper serration 41b (FIG. IOC).
  • incremental pitch 43 (FIG. 23D) between serration 41b and 41c of blocking sleeve 41 (FIG. IOC) is shown adjacent to aligned teeth 43a (FIG. 23D) (though alignment is not necessary for the pitch increment).
  • Blocking sleeve 41 may be rotated such that engagement between upper serration 41b and serration 18a of upper sub 18 occurs simultaneously with engagement between lower serration 41c and serration 27d of lower sub 27, regardless of the rotational alignment of serration 18a and serration 27d when tool joint 33 is properly assembled. Thus, it may not be necessary to compromise desired assembly torque to adjust the angular alignment of upper sub 18 and lower sub 27 for engagement with blocking sleeve 41, nor are match-fit parts required.
  • Bushing 20 includes an upper shoulder 20c (FIG. 10A) axially displacedfrom lower shoulder 20b (FIG. 10B) by an internal recess 20e which is disposed axially above internal diameter 20a; thus, a landing profile 20h is formed for landing and anchoring a UUT.
  • Internal diameter 18b (FIG. 10A), which is the internal diameter of the passage of the drill stem axially above upper sub 18, internal diameter 41a (FIG. IOC) of blocking sleeve 41, and internal diameter of the drill stem axially below may all be greater in diameter than internal diameter 20a, in order to allow for the passage of a UUT.
  • Shoulder 20f (FIG. 10B) and shoulder 41k (FIG. IOC) form recess 22b.
  • Recess 22b and diameter 20d provide radial clearance for the functioning of a UUT.
  • Tool joint 33 may be configured or specially lubricated such that it is properly assembled at a lower applied torque than other tool joints in a drill stem.
  • Upper thread 18c of upper sub 18 and lower thread 27c of lower sub 27 are part of and form tool joints of a drill stem (not shown). These tool joints and others of the drill stem are configured or lubricated to properly assemble at a higher applied assembly torque than tool joint 33.
  • Blocking sleeve 41 is disposed within upper sub 18 and lower sub 27.
  • Blocking sleeve 41 includes upper serration 41b that may be configured to engage compatible or mating serration 18a of upper sub 18, and lower serration 41c that may be configured to engage compatible or mating serration 27d of lower sub 27.
  • Blocking sleeve 41 when engaged, may prevent relative rotation between upper sub 18 and lower sub 27.
  • Blocking sleeve 41 also includes upper seal surface 41e, lower seal surface 41f (FIG. 10D), intermediate gap 41d (FIG. IOC), internal diameter 41a, upper end 41g of upper serration 41b, lower end 41h of lower serration 41c, upper end 41j and lower end 41i (FIG. 10D).
  • Blocking sleeve 41 is prevented from upward axial displacement by upper end 41j engaging shoulder 22a of spacer 22. Internal recess 22b (FIG. IOC) is disposed axially above shoulder 22a. Blocking sleeve 41 is prevented from downward axial displacement by engagement between lower end 41i and "c" ring 36 (FIG 10D).
  • Tool joint 33 is sealed by the contact of the rotary shoulders incorporated therein, while upper seal 23 and lower seal 32 function as debris barriers and maintain lubrication of serrations 18a, 41b, 27d and 41c.
  • Upper seal surface 41e may be the same or very nearly the same diameter as lower seal surface 41f to assure ease of movement in a high hydrostatic pressure fluid environment.
  • "c" ring 36 is held in a radially expanded condition within groove 27a of lower sub 27 by support surface 35c of lock sleeve 35.
  • Filler "c" ring 40 may be configured to be inserted within groove 27e in order to trap and transfer loads from retaining ring 39 and lower sub 27.
  • Ring 38 and shock absorber 37 which is possibly made of elastomeric material, secure lock sleeve 35 in position for lock sleeve 35 to axially support "c" ring 36 and transfer loads axially from shoulder 35d of lock sleeve 35 to retaining ring 39.
  • Retaining ring 39 is robust and may require a force to shear.
  • the force may be tens of thousands of pounds.
  • Lock sleeve 35 is lighter than blocking sleeve 41 and thus will create proportionately smaller inertial forces when subjected to the forces of rotary drilling.
  • Shock absorber 37 protects retaining ring 39 from the affects of vibration and impact shock that take place during rotary drilling.
  • Axial gap 44 between "c" ring 36 and the axial upper end of lock sleeve 35 assures that forces acting to move blocking sleeve 41 downward are transferred from blocking sleeve 41, through "c" ring 36, to the shoulder 27b of groove 27a of lower sub 27.
  • Internal diameter 41a of blocking sleeve 41 may be smaller than internal diameter 35a of lock sleeve 35, thereby providing protection from forces associated with lowering service tools through the drill stem, such as measurement while drilling tools and the like.
  • Internal diameter 20a may be smaller than internal diameter 41a of blocking sleeve 41.
  • Blocking sleeve 41 may be unlocked by displacing lock sleeve 35 axially downward.
  • a UUT engages shoulder 35b of lock sleeve 35, forcibly compelling shoulder 35d to axially compress shock absorber 37 and force ring 38 to shear retaining ring 39.
  • the UUT displaces lock sleeve 35 downwardly into a position where support surface 35c is no longer in position to axially support "c" ring 36 in the radially expanded position within groove 27a of lower sub 27.
  • Blocking sleeve 41 is prevented from further downward displacement when lower end 41i of blocking sleeve 41, acting through "c" ring 36, lock sleeve 35, shock absorber 37, ring 38, inner portion 39b, and shoulder 45a of "c” ring 45, engages shoulder 27s of lower sub 27.
  • Blocking sleeve 41 upon being fully displaced axially downward, serration 18a of upper sub 18 is disengaged from upper serration 41b of blocking sleeve 41 and lower serration 41c is disengaged from serration 27d of lower sub 27. Accordingly, upper end 41g of upper serration 41b is now disposed axially below "c" ring 34, preventing upper serration 41b of blocking sleeve 41 from returning to engagement with serration 18a of upper sub 18.
  • Torque applied in the opposite rotational direction from the torque applied during assembly will cause rotation between upper sub 18 and lower sub 27, as long as the portion of drill stem below lower body 26 is stuck or otherwise stabilized such that it will not rotate or move axially up or down. Continued rotation in the rotational direction opposite of that used in the assembly of tool joint 33 and lifting of the upper unstuck drill stem will disconnect the drill stem at tool joint 33.
  • Filler ring 40 may aid in assembly. Initially filler ring 40 is disposed within internal diameter 27q (FIG. 2E). Retaining ring 39, ring 38, shock absorber 37, lock sleeve 35, "c" ring 36 and blocking sleeve 41 are displaced downward by a UUT until retaining ring 39 engages shoulder 45a of "c" ring 45. In this configuration, lower serration 41c of blocking sleeve 41 and 18a of upper sub 18 are disengaged and upper sub 18 may be properly assembled to lower sub 27.
  • blocking sleeve 41 may be rotated for spline engagement, as discussed more fully above, and displaced upwardly until upper end 41j engages shoulder 22a of spacer 22.
  • "c" ring 36 forcibly compelled by lock sleeve 35, is displaced upwardly.
  • filler ring 40 is displaced axially upward to engage shock absorber 37 and retaining ring 39 with shoulder 35d of lock sleeve 35. In this position, filler "c” ring 40 may radially expand and engage shoulder 27f of lower sub 27.
  • Filler "c" ring 40 includes hole 40a and hole 40b to facilitate removal of filler "c” ring 40 from the groove 27e within lower sub 27.
  • “c” ring 36 includes hole 36a and hole 36b to facilitate removal of "c” ring 36 from lower sub 27.
  • “C” ring 34 includes hole 34a and hole 34b, "c” ring 19 has hole 19a and 19b, “c” ring 21 has hole 21a and 21b, "c” ring 45 has hole 45b and 45c for the same purpose.
  • an upper end includes a fishing neck 100 (FIG. 25A) connected to a mandrel 101 by threads 102.
  • Mandrel 101 is connected to upper control tube 103 (FIG. 25B) by threads 104, which is connected to intermediate control tube 105 (FIG. 25F) by threads 106 (FIG. 25E), which is connected to lower control tube 107 (FIG. 25G) with threads 108.
  • a body 109 (FIG. 25A) is connected to core 110 (FIG.
  • threads 111 which is connected to upper core extension 112 (FIG. 25F) by threads 135 (FIG. 25E), which is connected to core adapter 113 (FIG. 25F) by threads 114, which is connected to intermediate core extension 115 (FIG. 25G) by threads 116 (FIG. 25F), which is connected to lower core adapter 117 (FIG. 25G) by threads 118, which is connected to lower core extension 119 (FIG. 25H) by threads 120.
  • Grapple 121 (FIG. 25C) is connected to upper barrel 122 (FIG. 25E) by threads 123 with connector 124 clamped therebetween.
  • Upper barrel 122 is connected to intermediate barrel 125 (FIG. 25G) by threads 126 (FIG. 25F) with intermediate connector 127 therebetween.
  • Intermediate barrel 125 (FIG. 25G) is connected to protector 128 (FIG. 25H) by threads 129 (FIG. 25G) with lower connector 130 (FIG. 25H) therebetween.
  • collet 131 (FIG. 25B) is connected by shear pin 132 in hole 131p and hole 133a to lower ring 133.
  • Shear pin 152 is located opposite and is functionally identical to shear pin 132.
  • Upper ring 134 contacts shoulder 109o and spring 151.
  • key 136 (FIG. 25A) is radially movable in window 109a of body 109. Radial outward motion of key 136 is limited by shoulder 136a, shoulder 136b and bore 109d. Radial inward movement of key 136 is limited by surface 136c contacting diameter 101a.
  • Key 137, key 138 and key 139 (FIG. 28) are functionally identical and fitted for movement within body 109 the same as key 136. The interaction of key 136 with shoulder lOlf and diameter lOle will be addressed further during the discussion of the operation of the assembly below.
  • a bore sensor 142 is disposed in the body 109.
  • Bore sensor 142 is radially movable in hole 109i.
  • "C" ring 141 is within groove 101c and groove 109h preventing mandrel 101 from moving down with respect to body 109.
  • "C” ring 141 is biased radially outward, pushing sensor 142 outward. Radial outward motion of bore sensor 142 is stopped by flange 142a contacting groove 109h.
  • Bore sensors 143, 144, 145, 146 and 147 are functionally similar and fitted for movement within body 109 the same as bore sensor 142.
  • spring 151 forcibly compels collet 131, shear pin 132 and lower ring 133 downwardly.
  • the limit of downward motion is lower ring 133 contacting core 110.
  • Spring 151 is sufficiently forceful to overcome friction between "c" ring 148 and bore 131a.
  • Lower ring 133 is free to move upwardly against spring 151 along diameter 109n.
  • Spring 151 also urges upper ring 134 upwardly.
  • Upper ring 134 is prevented from upward movement along diameter 109n by shoulder 109o.
  • Collet 131 has finger 131d with lower external shoulder 131e, lower internal shoulder 131f, upper external shoulder 131g, upper internal shoulder 131h, internal surface 131i and external surface 131j.
  • the functional interface of lower internal shoulder 131f of collet finger 131d with diameter 109p and shoulder 109q of body 109 will be addressed during the discussion of the operation of the assembly below.
  • finger 131d is not biased inwardly for contact between internal surface 131i and diameter 109p.
  • Collet 131 has fingers 131k, 1311, 131m, 131n and 131o (FIG. 29) that are similar and functionally the same as finger 131d.
  • upper finger 121a (FIGS. 25C and 33) may be relaxed and in the inward position shown in FIG. 25C, with internal surface 121e adjacent diameter 110b.
  • Lower finger 121f (FIGS. 25D and 34) may be relaxed and in the inward position shown in FIG. 25D, with internal surface 121j adjacent diameter llOf.
  • Upper finger 121n, upper finger 121o, upper finger 121p, upper finger 121q and upper finger 121r (FIG. 33) are similar and functionally the same as upper finger 121a.
  • Lower finger 121s, lower finger 121t, lower finger 121u, lower finger 121v and lower finger 121w (FIG. 34) are similar and functionally the same as lower finger 121f.
  • fluid passage 1211, 103a and 110k assure fluid communication and equal pressure between the radially outer and inner cylindrical surfaces of grapple 121.
  • Shear screw 159 is secured within threaded hole 121m and within groove llOj, locating grapple 121 axially along core 110.
  • the interrelationship of external shoulder 121b, external surface 121d, external surface 121i, external shoulder 121g, lower external shoulder 131e, external surface 131j and shoulder 136d with the DSD 50 of FIGS. 1, 2A-2F, 3-8, 22, and 22A-22D will be addressed during the discussion of the operation of the assembly below.
  • chamber 179 is formed by seal surface 112a, seal 168, connector 124, seal 172, seal bore 122a, seal 173 and core adapter 113. Fluid passage 113a and the leak path of thread 114 are sealed by seal bore 112b, seal 160, intermediate control tube 105, seal 161 and seal bore 113b.
  • chamber 180 is formed by seal surface 115a, seal 169, intermediate connector 127, seal 174, seal bore 122a, seal 173 and core adapter 113. Fluid passage 113c and the leak path of thread 116 are sealed by seal bore 113b, seal 162, intermediate control tube 105, seal 163 and seal bore 115b.
  • chamber 181 (FIG. 25G) is formed by seal surface 115a, seal 169, intermediate connector 127, seal 175, seal bore 125a, seal 176 and lower core adapter 117. Fluid passage 117a and the leak path of thread 118 are closed by seal bore 115b, seal 164, lower control tube 107, seal 165 and seal bore 117b. Chamber 182 (FIG. 25H) is formed by seal surface 119a, seal 170, lower connector 130, seal 178, seal bore 125a, seal 176 and lower core adapter 117. Fluid passage 117c and the leak path of thread 120 are sealed by seal bore 117b, seal 166, lower control tube 107, seal 167 and seal bore 119b.
  • fluid passage 183 extends through the interior of protector 128, seal bore 119b to seal 167, lower control tube 107 (FIG. 25G), through fluid passage 107a, seal bore 117b between seal 165 and seal 166, intermediate control tube 105 (FIG. 25F), through fluid passage 105b, seal bore 115b between seal 163 and seal 164, through fluid passage 105a, seal bore 113b between seal 161 and seal 162, upper control tube 103 (FIG. 25E), through fluid passage 103a, which is open to hydrostatically pressurized fluid 184 (FIG. 25H), mandrel 101 (FIG. 25A), fishing neck 100 and thru fluid passage 100a.
  • high hydrostatically pressurized fluid 184 may enter fluid passage 183 and surround chamber 179 (FIG. 25E), chamber 180 (FIG. 25F), chamber 181 (FIG. 25G) and chamber 182 (FIG. 25H).
  • Seal bore 119b (FIG. 25H), seal bore 117b (FIG. 25G), seal bore 115b, seal bore 113b (FIG. 25F) and seal bore 112b, are substantially the same. There is no or very little force caused by high hydrostatically pressurized fluid 184, as would exist deep within a fluid filled well, to move the fishing neck 100 up or down.
  • chamber 179, chamber 180, chamber 181 and chamber 182 contain air at or near the atmospheric pressure in which they were assembled. Seal surface 112a (FIG. 25F) and seal surface 119a (FIG. 25H) are the same or very nearly the same diameter; thus, there is a balancing upward force acting on lower connector 130 against a downward force acting on connector 124 (FIG. 24E).
  • grapple 121 and core 110 are designed such that high pressure fluid 184 surrounding the UUT may not result in the severing of shear screw 159.
  • Allowing hydrostatically pressurized fluid 184 within chamber 180 creates a downward force on intermediate connector 127 and an upward force on core adapter 113. Allowing hydrostatically pressurized fluid 184 within chamber 182 (FIG. 25H) eliminates the upward force upon lower connector 130 that acted to balance the downward force upon core adapter 124 (FIG. 25E),which creates an upward force on lower core adapter 117 (FIG. 25G).
  • key 136 will be inclusive of functionally identical key 137 (FIGS. 25A and 28), key 138, and key 139.
  • Bore sensor 142 (FIGS. 25B and 29) will be inclusive of functionally identical bore sensor 143, bore sensor 144, bore sensor 145, bore sensor 146 and bore sensor 147.
  • Ball 150 (FIGS. 25B and 30) will be inclusive of functionally identical ball 154, ball 155, ball 156, ball 157 and ball 158.
  • Shear pin 152 (FIGS. 25B and 32) will be inclusive of functionally identical shear pin 153.
  • a well includes multiple DSD's installed at intervals along the length of a rotary drill stem.
  • the spacing, number and location Of the DSD's is based on a risk analysis by those responsible for the drilling program. For example, one DSD may be connected between every nine joints of drill pipe, starting at two thousand feet above the drill bit and continuing to the surface. Thus, there would be twelve disconnects in the well. Further, the drill pipe could be stuck such that the drill pipe will not move up or down, cannot be rotated and circulation of drill fluids is not possible. The pipe could then be stretched and relaxed to hypothetically determine that the pipe is stuck below the eighth DSD.
  • a UUT 90 would be connected to a conventional wireline unit, with appropriate weight bar, jars, running tool and the like (not shown), via the fishing neck 100.
  • the UUT 90 is lowered, then raised and lowered again within the well drill stem.
  • "C" ring 140 (FIG. 25A) is within groove 101b and shoulder 109e receives the weight of the UUT 90 and transmits upward forces from the wireline (not shown) in all of the motions.
  • mandrel 101 and body 109 do not move relative to one another and thus the lower portions of the UUT 90 are inactive.
  • FIG. 47A shows the portion of the UUT 90 described previously in FIG. 25B, as it is received within the first DSD 50 of the twelve identical DSD's of this exemplary situation.
  • Arrow 186 indicates the direction of the axial motion of UUT 90.
  • Outer diameter 110m of core 110 slides axially through internal diameter la of upper body 1, with a clearance existing between the two diameters.
  • the external surface 131j passes through internal diameter lg with a clearance existing between the two diameters.
  • Bore 131a prevents the radially outward biased "c" ring 148 from expanding outwardly, and because of ball 150, radially outward biased "c” ring 149 is prevented from expanding outwardly.
  • C C
  • ring 149 is within groove lOld and groove 109m, preventing relative movement between mandrel 101 and body 109.
  • Bore sensor 142 is radially displaced outward by "c" ring 141 and is disposed within groove 101c and 109h, preventing relative movement between mandrel 101 and body 109.
  • Shear pin 132 remains unsevered and spring 151 forcibly urges collet 131 downward.
  • FIG. 47B shows the portion of the UUT 90 described previously in FIG. 25B, as it is lowered further into the DSD 50 and downwardly displaced from its position illustrated in FIG. 47A, but still within the first of the twelve identical DSD's of this exemplary situation.
  • Arrow 186 indicates the direction of motion of the UUT 90.
  • lower exterior shoulder 131e contacts lower shoulder lb, forcibly preventing collet 131 from further travelling downward.
  • diameter 109p slides under internal surface 131i compressing spring 151 until finger 131d is no longer supported by diameter 109p.
  • FIG. 47C shows continued downward movement of the UUT 90 through the DSD 50.
  • upper external shoulder 131g slides axially downward and radially outwards along shoulder li and external surface 131j moves axially out of internal diameter la.
  • Shear pin 132 is remains unsevered and spring 151 forcibly moves collet 131 downward to a position of lower ring 133, causing collet 131 to contact core 110.
  • Finger 131d moves radially outward to a relaxed position with internal surface 131i radially adjacent diameter 109p.
  • Bore sensor 142 returns to the radial outward position by the outward urging of radially biased "c” ring 141 as “c” ring 141 returns to its initial position within groove 101c and groove 109h, preventing relative axial movement between mandrel 101 and body 109.
  • Bore 131a prevents "c” ring 148 from radially expanding outward, and because of ball 150, "c” ring 149 is prevented from radially expanding outward.
  • “C” ring 149 is disposed within groove lOld and groove 109m, preventing relative axial movement between mandrel 101 and body 109.
  • the UUT 90 has now returned to the condition as shown in FIG. 47A; however, now in the position shown in FIG. 47C, instead of the outer diameter 110m of core 110 being within internal diameter la of upper body 1, outer diameter 110m of core 110 is now within internal diameter 3a of blocking sleeve 3 with clearance, existing between the two diameters.
  • the UUT 90 is lowered downward at a high enough acceleration to create sufficient velocity for the momentum of the weight bar, jars, running tool and UUT to sever shear pin 152 of FIG. 25B.
  • FIG. 47D shows the portion of the UUT 90 previously described in FIG. 25B, as it is raised upward through, but still within, the eighth of twelve identical DSD's in this exemplary situation.
  • Arrow 188 indicates the direction of the upward motion of UUT 90.
  • external surface 131j passes through blocking sleeve 3 with a clearance between the two surfaces, and upper external shoulder 131g contacts shoulder li, forcibly preventing collet 131 from any further upward movement.
  • momentum of UUT 90 carries core 110 upward, which in turn forcibly compels lower ring 133 upward, severing shear pin 132.
  • spring 151 no longer pushes collet 131 downward, as shear pin 132 is now severed and lower ring 133 is no longer connected to collet 131.
  • Spring 151 now acts to radially expand collet 131 as end surface 134a of upper ring 134 contacts shoulder 131b.
  • Body 109 then begins moving upward within collet 131, with diameter 109p moving upward and sliding under internal surface 13 li of collet 131.
  • Core 110 moves upward and forcibly compels lower ring 133 to compress spring 151.
  • FIG. 47E shows the position of UUT 90 as it is displaced upward from the position shown in FIG. 47D, while still within the eighth of twelve identical DSD's in this exemplary situation.
  • Arrow 188 indicates the direction of motion of the UUT 90.
  • outer diameter 110m of core 110 is disposed within internal diameter 3a of blocking sleeve 3.
  • FIG. 47F shows a portion of UUT 90 as it is displaced upward, above the eighth of the twelve identical DSD's in this exemplary situation.
  • Arrow 188 indicates motion of the UUT in either direction.
  • Bore sensor 142 upon exiting internal diameter la due to its upward displacement, is radially displaced outward by "c" ring 141, disposing it within groove 101c and 109h, preventing relative axial movement between mandrel 101 and body 109.
  • outer diameter 110m of core 110 is disposed within internal diameter la of upper body 1.
  • Spring 151 forcibly compels upper ring 134 axially against shoulder 131b, axially displacing collet 131 upward such that shoulder 131r engages "c" ring 148 within groove 109k.
  • Finger 131d is disposed in the relaxed position with internal surface 131i supported on diameter 109p.
  • "C" ring 141 is disposed radially within both groove 101c and in groove 109h, preventing relative axial movement between mandrel 101 and body 109.
  • Bore sensor 142 is disposed in a radially outward position. Shear pin 132 is severed and spring 151 now urges collet 131 upward.
  • FIG. 47G shows a portion of the UUT 90 as it is axially displaced downward into the eighth of the twelve identical DSD's in the hypothetical drill stem of this exemplary situation.
  • Arrow 190 indicates axial motion of UUT 90.
  • Finger 131d is disposed in the relaxed position with internal surface 131i supported on diameter 109p.
  • Lower external shoulder 131e of collet 131 engages lower shoulder lb and axial downward movement of the body 109 is prevented by the engagement of "c" ring 148, which is radially disposed within both groove 109k and shoulder 131r.
  • an embodiment of UUT 90 may be selectively landed in any one of multiple DSD's and be retrieved from the well at any time.
  • the functioning of an embodiment of the UUT to unlock and unblock a DSD will be explained.
  • the following actions performed by an embodiment of the UUT are initiated by relative axial movement of fishing neck 100 with respect to body 109.
  • FIGS. 48A-48E, 49A-49E, 50A-50E, 51A-51E, 52A-52E, 53A-53E and 54A-54E are sectional views showing progressive operation of the components of the embodiment of UUT 90 shown in FIGS. 25A-25H and 26- 46 and the embodiment of DSD 50 shown in FIGS. 1, 2A-2F, 3-8, 22 and 22A- 22D.
  • Hydrostatically pressurized fluid 184 is located within fluid passage 183, completely surrounding UUT 90, within the drill stem connected axially upward of body 1, within DSD 50, and in the stuck drill stem connected axially downward of lower body 2.
  • fishing neck 100 (FIG. 25A) is connected to mandrel 101, upper control tube 103 (FIG. 25C), intermediate control tube 105 (FIG. 25F) and lower control tube 107 (FIG. 25G).
  • body 109 (FIG. 25A) is connected to core 110 (FIG. 25B), upper core extension 112 (FIG. 25F), core adapter 113, intermediate core extension 115 (FIG. 25G), lower core adapter 117 and lower core extension 119 (FIG. 25H).
  • Grapple 121 (FIG. 25C) is connected to upper barrel 122 (FIG. 25E), connector 124, intermediate connector 127 (FIG. 25F), intermediate barrel 125 (FIG. 25G), lower connector 130 (FIG. 25H) and protector 128.
  • collet 131 has landed on and engaged shoulder lb, preventing axial downward movement of body 109, as shown in FIG. 48A.
  • Body 109 is connected to grapple 121, by shear screw 159 (FIG. 48C).
  • FIG. 48D Although fishing neck 100 has been axially displaced in relation to body 109, flow passages 113a, 113c, 105a, 105b, 117a, 117c and 107a are all blocked, as shown in FIG. 48D.
  • Chambers 179 (FIG. 48C), 180, 181 and 182 (FIG. 48D) may be preassembled and thus contain air at or near atmospheric pressure.
  • Seal surface 112a (FIG. 49C) and seal surface 119a (FIG. 49D) may be structurally similar.
  • high hydrostatically pressurized fluid 184 surrounding DSD 50 and within passage 183 will not result in the application of forces or relative motion between grapple 121 and core 110 that would sever shear screw 159.
  • diameter 110b of core 110 (FIG. 48B) is disposed radially adjacent of internal surface 121e of upper finger 121a.
  • External surface 121d of upper finger 121a is displaced axially downward from internal diameter la of upper body 1, where internal diameter la is smaller than internal diameter 3a of blocking sleeve 3, which in turn is smaller than internal diameter 4a of lock sleeve 4.
  • Diameter llOf of core 110 is disposed radially adjacent of internal surface 121j of lower finger 121f.
  • External surface 121i of lower finger 121f is displaced downward from internal diameter la.
  • the weight of the wireline tools results in the downward axial displacement of fishing neck 100 (FIG. 49A)until end surface lOlh of mandrel 101 engages end surface 110a of core 110. Due to this axial displacement, "c" ring 140 has radially expanded within groove 109g of body 109 and is no longer radially disposed within groove 101b of mandrel 101. Flow passages 113a, 105b and 117a (FIG. 49D) remain blocked. Thus, chambers 179 (FIG. 49C) and 181 (FIG. 49D) continue to contain air at or near atmospheric pressure.
  • passages 113c, 105a, 117c and 107a are now in fluid communication with hydrostatically pressurized fluid 184 via passage 183 (FIG. 49E).
  • Chamber 180 and chamber 182 now begin to rapidly fill with hydrostatically pressurized fluid 184.
  • chamber 180 applies an axial downward force on intermediate connector 127 (FIG. 49D) and an axial upward force on core adapter 113.
  • chamber 182 applies an axial downward force on lower connector 130, effectively removing the axial upward force of lower connector 130 acting to balance the axial downward force of core adapter 124; chamber 182 also applies an axial upward force on lower core adapter 117.
  • filling chamber 180 and chamber 182 with pressurized fluid 184 forcibly compels grapple 121 axially downward and, with equal and opposite magnitude, forcibly compels body 109 axially upward.
  • FIGS. 50A-50E pressure within chamber 180 and chamber 182 (FIG. 50D) has, at this point, increased sufficiently to sever retaining ring 8 into outer portion 8a and inner portion 8b (FIG. 50C). Due to the severing of retaining ring 8, grapple 121 and connected parts have displaced axially downward.
  • Surface 121j of lower finger 121f radially supported by surface llOh with external shoulder 121g engaging shoulder 4b, has axially displaced lock sleeve 4 downward such that support surface 4c is no longer axially disposed within "c" ring 5.
  • Internal surface 121e (FIG.
  • grapple 121 (FIG. 51C) has been further axially displaced downward, such that finger 121f has been radially displaced inward with internal surface 12 lj and is now disposed radially adjacent diameter 110 ⁇ of core 110.
  • locking sleeve 4 is no longer engaging grapple 121.
  • Finger 121a (FIG. 51B), with internal surface 121e radially supported by diameter llOd, has forcibly compelled blocking sleeve 3 axially downward such that upper seal 10 no longer engages upper seal surface 3e.
  • grapple 121 (FIG. 52B) has been further axially displaced downward.
  • Blocking sleeve 3 has been fully displaced downward such that serration Id of upper body 1 is no longer engaging upper serration 3b of blocking sleeve 3.
  • "c" ring 11 radially adjacent upper seal surface 3e and axially upward from upper end 3g of upper serration 3b, prevents upper serration 3b from re-engaging serration Id.
  • Finger 121a has been radially displaced inward with internal surface 121e now disposed adjacent diameter llOf of core 110.
  • shoulder 136d (FIG. 52A) no longer engages shoulder If. Collet 131 is again in engagement with shoulder lb, preventing downward axial displacement of UUT 90.
  • grapple 121 (FIG. 53C), no longer engaged with either locking sleeve 4 or blocking sleeve 3, has been fully displaced axially downward.
  • chambers 179 and 181 (FIG. 53D)
  • minor pressure and temperature changes have occurred during this process to the atmospheric air trapped during assembly of the UUT 90.
  • the pressure changes within these two chambers are insignificant in relation to the high hydrostatic pressures that exist deep within a fluid filled well, and thus the trapped air within chambers 179 and 181 is considered near atmospheric pressure.
  • chambers 180 and 182 are filled with hydrostatically pressurized fluid 184.
  • the drill stem situated axially upward from upper body 1 (not shown) and upper body 1 are both rotated in the opposite direction from the rotational position used to assemble the rotary shouldered and threaded connection of tool joint 15 (Fig. 54B) and then lifted upward such as to disconnect upper half 15a of upper body 1 from lower half 15b of lower body 2.
  • Collet 131 engages lower shoulder lb and elevates UUT 90 with the upper unstuck portion of the drill stem.
  • UUT 90 may be upwardly removed with the upper drill stem.
  • the wireline unit may be disconnected and fishing neck 100 left down or up. Passage 183 is open to drain fluids as the drill stem is elevated.
  • fishing neck 100 may be displaced upwardly such that groove 101b axially passes "c" ring 140, shoulder lOlg of mandrel 101 engages shoulder 109s of body 109, key 136 is radially displaced outward, surface 136c is radially adjacent diameter 101a, and flow passages 113a, 105b, 117a, 113c, 105a, 117c and 107a (FIG. 54D) are now all open to hydrostatically pressurized fluid 184 via passage 183 (FIG. 54E). Chambers 179, 180, 181 and 182 are filled with pressurized fluid 184 and are at similar pressures.
  • UUT 90 may be broken apart at threads 123, 135 and 106 (FIG. 25E) and axially lengthened by adding: an additional intermediate control tube 105 (FIG. 25F) with seals 160, 161, 162 and 163, an additional upper core extension 112, an additional upper barrel 122 (FIG. 25E), an additional intermediate connector 127 (FIG. 25F) with seals 174, 175 and 163, and an additional core adapter 113 with seal 173. Reassembly of UUT 90 with this additional segment will add another atmospheric chamber and another pressurized chamber. This addition may be repeated as many times as desired to allow UUT 90 to be used shallower in a well that cannot be pressurized from the surface.
  • a DSD and UUT may also include alternative embodiments.
  • a DSD 200 includes an axially inverted block and lock sleeve mechanism including a block sleeve 203 and a lock sleeve 204.
  • the positions of block sleeve 203 and lock sleeve 204 are reversed or inverted compared to the similar structures of the DSD 50 shown in FIGS. 2A-2F.
  • Also axially inverted compared to similar components of DSD 50 are the first mating serrations 206 and the second mating serrations 208 between block sleeve 203 and body 202.
  • DSD 200 also includes a first tool joint 215 and a second tool joint 214.
  • the other features of inverted DSD 200 may be substantially the same as those shown and described with reference to DSD 50 of FIGS. 2A-2F.
  • UUT 250 includes an upper end similar to the same portion of UUT 90 in FIGS. 25A and 25B.
  • UUT 250 also includes an inner core 252 and a grapple 254 similar to grapple 121 but with some differences.
  • Grapple 254 includes an upper collet mechanism with a plurality of collets fingers 256 (FIG. 58), a lower collet mechanism with a plurality of collets fingers 260 (FIG. 60) and a shear member 253.
  • grapple 254 of UUT 250 is inverted such that engagement members 258, 262 of the collet fingers 256 and 260 are directed in the opposite axial direction relative to the similar members of grapple 121 of UUT 90.
  • the axially inverted collets of UUT 250 are adapted for operational interaction with the appropriate portions of the axially inverted DSD 200 described above, in a manner similar to that described above with respect to UUT 90 and DSD 50.
  • UUT 250 also includes an axially inverted lower hydraulic and atmospheric chamber portion as compared to UUT 90.
  • the lower hydraulic and atmospheric chamber portion of UUT 250 is axially inverted such that a connector 270 (FIG. 61) is disposed at an upper end of this portion of UUT 250 radially inside outer barrel 264, forming a chamber 282.
  • a chamber 281 (FIG. 62) formed between radially outer barrel 264 and radially inner core 266.
  • an intermediate connector 268 partially defines a chamber 280; also, a chamber 279 is disposed within this portion of UUT 250 and is partially defined by lower connector 272, outer barrel 264 and inner core 266.
  • UUT 250 also includes lower end fluid passage 283.
  • the operation of the inverted lower hydraulic and atmospheric chamber portion of UUT 250 is similar in manner as compared to the corresponding chamber portion of UUT 90.
  • block sleeve 203 of DSD 200 shifts axially upward upon activation of the assembly and the disconnection is made in a manner similar as previously described with regard to UUT 90 and DSD 50, at the lower tool joint 215 shown in FIG. 57.
  • DSD 300 is illustrated which is axially inverted and includes a shear or frangible release in place of the lock sleeve.
  • DSD 300 comprises a body 302 (FIG. 65) with no tool joint axially adjacent to the upper end of a block sleeve 303. Instead a tool joint 315 is disposed toward the axially lower portion of block sleeve 303 (FIG. 66).
  • Block sleeve 303 includes an axially upper portion 303a and an axially lower portion 303b coupled by a threaded connection 303c.
  • a lower shearable or frangible release mechanism 310 radially engages both block sleeve 303 and body 302 until activation of the assembly occurs in response to a UUT as described herein.
  • mechanism 310 Upon the application of an upward force by a UUT, mechanism 310 shears or releases to allow the upper end 312 of block sleeve 303 to move axially upward into a bore space 314 of body 302 (FIG. 65), thereby axially disengaging mating serrations 306, 308, and allowing the upper and lower tubular strings to be disconnected at the tool joint 315.
  • Other features of DSD 300 not specifically described herein are consistent with corresponding features of the DSD's described elsewhere in this description.
  • a DSD 400 is also axially inverted as compared to DSD 50, but also includes a lower lock mechanism 409 (FIG. 68) rather than the shear mechanism 310 of DSD 300.
  • a lock sleeve 414 (FIG. 68)
  • a collet mechanism 410 of the lower lock mechanism 409 Upon activation of the assembly in response to a UUT as described herein, an upward force is applied to a lock sleeve 414 (FIG. 68) and a collet mechanism 410 of the lower lock mechanism 409, releasing a block sleeve 403.
  • Lower lock mechanism 409 comprises an axial lower portion 403b and an axial upper portion 403a of block sleeve 403, coupled by a threaded connection 403c.
  • the released block sleeve 403 is displaced axially upward such that an upper end 412 of block sleeve 403 is displaced axially into a bore space 414 of a body 402 (FIG. 67), thereby axially disengaging mating serrations 406, 408, and allowing the upper and lower tubular strings to be disconnected at the tool joint 415.
  • Other features of DSD 400 not specifically described herein are consistent with corresponding features of the DSD's contained elsewhere in this description.
  • the DSD's 300, 400 include only one rotary shouldered and threaded tool joint and one lock or release mechanism, thus only requiring one collet mechanism in the respective activating UUT.
  • An alternative embodiment of a UUT is illustrated in FIGS. 69-71.
  • UUT 450 is designed to activate inverted DSD's 300, 400, and thus it shares many of the same features and characteristics of the previously described UUT 250.
  • the upper fishing neck and collet portion of UUT 450 corresponds to the fishing neck and collet portion of UUT's 50, 250, of FIGS. 25A and 25B.
  • the lower chamber portion of UUT 450 corresponds to the lower chamber portion of UUT 250, shown in FIGS. 61-64.
  • UUT 450 includes a grapple 454 (FIG. 70) with only a single collet mechanism including a plurality of collets fingers 456 and a shear member 453.
  • the axially inverted collet mechanism includes engagement members 458 of the collet fingers directed in the axially opposed direction of the engagement members of the grapple 121 of UUT 90.
  • the collet mechanism of the UUT 450 is configured for operational interaction with the single, lower release or lock mechanism of the inverted DSD's 300, 400, described above.
  • FIGS. 72-77 Another embodiment of a disconnect assembly relates to the use of serrations to rotationally couple two bodies of a disconnect assembly using a third body with a varying number of serrations on each body, and is shown in FIGS. 72-77.
  • First body 500 (FIG. 72) may be a solid or hollow object of any shape fitted with a generally cylindrical end with serrations 500a disposed radially about an outer circumference of first body 500.
  • Second body 501 may be a solid or hollow object of any shape fitted with a generally cylindrical end with serrations 501a disposed radially about an outer circumference of second body 501.
  • Serrations 500a of first body 500 and serrations 501a of second body 501 are of different count or pitch.
  • a third body 502 is fitted with serrations 502a disposed radially about an inner circumference of third body 502 for companion engagement with serrations 500a of first body 500, and serrations 502b disposed radially about the inner circumference of third body 502 but axially displaced from serrations 502a for companion engagement with serrations 501a of second body 501.
  • Sufficient axial clearance must be provided such that serrations 502a and 502b of third body 502 may disengage from their respective mating serrations 500a and 501a, to allow third body 502 to be rotated independently of first body 500 and second body 501.
  • Axial gap 503 disposed axially upward from serration 500a must be of sufficient width to allow the third body 502 to be axially displaced upward to disengage serration 502a from serration 500a of first body 500 and, assuming serration 502b would interfere by engaging serration 500a, axial gap 504 between serrations 500a and 501a must be sufficient to allow the third body 502 to be axially displaced upward to disengage serration 502b from serration 501a of second body 501.
  • Screws 505a and 505b retained by nuts 506a and 506b extend radially through second body 502, holding third body 502 in the engaged position as shown in FIG. 72.
  • first body 500 and second body 501 are immovable or positioned in a desired rotational position with respect to one another
  • the third body 502, axially positioned such that serration 502a is aligned in gap 503 and serration 502b is aligned in gap 504 may be rotated into a particular position and axially engaged with the serrations of the first body 500 and the second body 501 by axially displacing third body 502 such that serration 502a engages serration 500a and serration 502b engages serration 501a, to prevent rotation between first body 500 and second body 501.
  • first body 500 and the second body 501 may be shaft couplings within a machine or a sign post and a ground fitting.
  • the bodies 500, 501 include not just downhole tubulars, but tubular or cylindrical members in fields outside of hydrocarbon exploration and production.
  • FIGS. 78-88 Yet another embodiment of a disconnect assembly using serrations to rotationally couple two bodies using a third body, with a different number of serrations on each body is shown in FIGS. 78-88.
  • the first body 507 (FIG. 78) is in the form of a shaft including a key slot 507b (FIG. 83) disposed axially along the circumference of a central bore 507c and a threaded set screw hole 507d (FIG. 80) extending radially away from first body 507 for mounting on a shaft 510 disposed concentrically within first body 507 using a circumferentially disposed key 511.
  • First body 507 has a serrated face 507a (FIGS. 82, 83).
  • the second body 508 is in the form of a shaft including a key slot 508b (FIG. 84) disposed axially along the circumference of a central bore 508c and a threaded set screw hole 508d (FIG. 508D) extending radially away from second body 508 for mounting on a shaft 512 disposed concentrically within second body 508 using a circumferentially disposed key 513.
  • Second body 508 has a serrated face 508a (FIGS. 84, 85). Serrations 507a of first body 507 and serrations 508a of second body 508 are of different count or pitch.
  • a third body 509 (FIG. 80) is fitted with serrations 509a (FIG. 87) disposed on a face of third body 508 for companion engagement with serrations 507a of first body 507, and serrations 509b disposed on an opposite face of third body 508 for companion engagement with serrations 508a of second body 508.
  • Circumferentially disposed about the axial engagement between first body 507, second body 508, and third body 509 are semi-cylindrical retainers 514 and 515 (FIG. 78).
  • Retainer 515 and retainer 514 surround and act to hold first body 507, second body 508 and third body 509 in companion serration engagement.
  • Retainer 515 and retainer 514 are secured in engagement about first body 507, second body 508 and third body 509 by studs 516a, 516b, nuts 517a, 517b, 517c and 517d (FIG. 81).
  • first body 507 and serrations 508a of second body 508 may be disengaged from the companion serrations 509a and 509b of third body 509 and first body 507 and second body 508 may be rotated in relation to one another to form a new angular relationship.
  • Retainers 514 and 515 may then be reinstalled as previously described depending on clearances and number of or angular pitch of the pairs of serrations.
  • first body 507 and second body 508 may be formed integrally with shafts 510 and 512 so long as freedom exists to move the shaft mountings axially apart to position and engage the serration pairs 509a and 509b formed with third body 509.
  • tool joints of the drill stem including tool joint 15 of FIG. 2C may be identical but assembled with different lubricants, or they may be of different design but assembled with the same lubricant, or a mixture of different designs and lubricants and not deviate from the scope and spirit of the principles disclosed herein.
  • the exemplary situation given above is by way of example only, and other embodiments may include one DSD or any number of DSD's used at any depth, at regular or random spacing intervals so long as adequate hydrostatic or applied pressure is available.
  • Wireline was used in the exemplary situation to lower and raise the UUT within the drill stem, though other common methods may be used with this description such as coiled tubing, pump down, macaroni tubing, sand line and the like. Circulation was not possible in the exemplary situation described above to display the versatility of the embodiments disclosed herein, though circulation is often desirable and would aid, not inhibit, the function of the described UUTs.

Landscapes

  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Mechanical Engineering (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention concerne un ensemble permettant de séparer des parties d'une colonne de tubage de fond, comme une tige de forage ou un train de tiges de forage, et de retirer une partie supérieure du train de tiges tubulaire depuis la partie enfoncée inférieure dans un puits. L'ensemble de séparation comprend une liaison entre les joints de deux parties du train de tiges tubulaire. L'ensemble comprend deux éléments tubulaires et un manchon interne comprenant deux cannelures présentant chacune des pas angulaires ou des nombres de dents différents. L'ensemble peut comprendre une liaison filetée épaulée rotative, les deux parties tubulaires pouvant être séparées au niveau de la liaison filetée épaulée rotative dans l'ensemble. L'ensemble peut comprendre un verrou de manchon, un dispositif d'interdiction sélective pour la réception dans un profil et un outil de déverrouillage et de déblocage pouvant être déployé sélectivement pour l'activation de l'ensemble. L'ensemble peut comprendre des éléments cylindriques pouvant être reliés autres que des éléments tubulaires de fond.
PCT/US2012/027011 2011-02-28 2012-02-28 Ensemble de séparation pour éléments cylindriques WO2012118851A2 (fr)

Priority Applications (2)

Application Number Priority Date Filing Date Title
CA2828486A CA2828486C (fr) 2011-02-28 2012-02-28 Ensemble de separation pour elements cylindriques
EP12751793.6A EP2681405B1 (fr) 2011-02-28 2012-02-28 Ensemble de séparation pour éléments cylindriques

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201161447471P 2011-02-28 2011-02-28
US61/447,471 2011-02-28

Publications (2)

Publication Number Publication Date
WO2012118851A2 true WO2012118851A2 (fr) 2012-09-07
WO2012118851A3 WO2012118851A3 (fr) 2012-11-22

Family

ID=46232843

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/027011 WO2012118851A2 (fr) 2011-02-28 2012-02-28 Ensemble de séparation pour éléments cylindriques

Country Status (4)

Country Link
US (2) US9512683B2 (fr)
EP (1) EP2681405B1 (fr)
CA (2) CA2894001C (fr)
WO (1) WO2012118851A2 (fr)

Families Citing this family (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9114458B2 (en) 2009-08-21 2015-08-25 Illinois Tool Works Inc. Pipe end machining device with axial autofeed
GB2496913B (en) * 2011-11-28 2018-02-21 Weatherford Uk Ltd Torque limiting device
US20150069752A1 (en) * 2013-09-06 2015-03-12 Baker Hughes Incorporated Modular Tubing Seal Bore System
WO2015051111A1 (fr) 2013-10-03 2015-04-09 Illinois Tool Works Inc. Support d'outil pivotant pour appareil d'usinage de tuyaux
US9834997B2 (en) * 2015-02-24 2017-12-05 Onesubsea Ip Uk Limited Tool connection release system
US10072471B2 (en) * 2015-02-25 2018-09-11 Baker Hughes Incorporated Sponge liner sleeves for a core barrel assembly, sponge liners and related methods
WO2018140462A1 (fr) * 2017-01-24 2018-08-02 Enventure Global Technology, Inc. Raccord double femelle de sécurité à actionnement hydraulique
US20180305984A1 (en) * 2017-04-25 2018-10-25 Vetco Gray Inc. Self-limiting c-ring system and method
US11927067B2 (en) 2021-11-30 2024-03-12 Baker Hughes Oilfield Operations Llc Shifting sleeve with extrudable ball and dog
US11891868B2 (en) * 2021-11-30 2024-02-06 Baker Hughes Oilfield Operations Llc Extrusion ball actuated telescoping lock mechanism
US11814926B2 (en) 2021-11-30 2023-11-14 Baker Hughes Oilfield Operations Llc Multi plug system
US11891869B2 (en) 2021-11-30 2024-02-06 Baker Hughes Oilfield Operations Torque mechanism for bridge plug

Family Cites Families (35)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1559874A (en) 1924-08-29 1925-11-03 Samuel E Holland Tool joint
US1883071A (en) * 1928-12-14 1932-10-18 Doheny Stone Drill Co Lockable safety joint
US2176504A (en) * 1938-07-18 1939-10-17 James E Mclaughlin Pipe coupling detachable locking device
US2586015A (en) 1940-05-13 1952-02-19 Edwards Frances Robertha Pipe releasing means
US2302856A (en) * 1940-08-10 1942-11-24 Weslie M Hamon Releasable joint for rotary well strings
US3112796A (en) * 1961-03-30 1963-12-03 Baker Oil Tools Inc Hydraulically actuated well packers
US3622185A (en) * 1969-06-02 1971-11-23 Rosan Inc Locking assembly for high-speed shafts
US3638723A (en) * 1970-06-22 1972-02-01 Otis Eng Co Locator devices
US3895829A (en) 1974-02-04 1975-07-22 Halliburton Co Releasable pipe connector
US4693498A (en) * 1986-04-28 1987-09-15 Mobil Oil Corporation Anti-rotation tubular connection for flowlines or the like
JPS63268895A (ja) * 1987-04-08 1988-11-07 インコ、リミテッド ドリル刃と衝撃ハンマ、および刃保持リング
US4823872A (en) * 1988-04-22 1989-04-25 Baker Hughes Incorporated Downhole locking apparatus
US5146984A (en) 1991-04-09 1992-09-15 Otis Engineering Corporation Emergency release device for connecting between tubular members in oil and gas wells
US5323853A (en) * 1993-04-21 1994-06-28 Camco International Inc. Emergency downhole disconnect tool
US5819854A (en) * 1996-02-06 1998-10-13 Baker Hughes Incorporated Activation of downhole tools
WO1998029637A1 (fr) 1996-12-31 1998-07-09 Helms Charles M Dispositif de tete d'injection verrouillable et procede correspondant
US5984029A (en) 1997-02-06 1999-11-16 Baker Hughes Incorporated High-load hydraulic disconnect
US6186249B1 (en) 1998-01-14 2001-02-13 Thor Bjornstad Release equipment for a drill string
US6131953A (en) 1998-06-02 2000-10-17 Halliburton Energy Services, Inc. Coiled tubing drilling hydraulic disconnect
US6318470B1 (en) 2000-02-15 2001-11-20 Halliburton Energy Services, Inc. Recirculatable ball-drop release device for lateral oilwell drilling applications
US6408946B1 (en) * 2000-04-28 2002-06-25 Baker Hughes Incorporated Multi-use tubing disconnect
US6712146B2 (en) 2001-11-30 2004-03-30 Halliburton Energy Services, Inc. Downhole assembly releasable connection
US6516901B1 (en) * 2002-04-01 2003-02-11 Thomas E. Falgout, Sr. Adjustable orienting sub
US7390032B2 (en) * 2003-08-01 2008-06-24 Sonstone Corporation Tubing joint of multiple orientations containing electrical wiring
NO20034158L (no) * 2003-09-18 2005-03-21 Hydralift Asa Laseanordning av sammenskrudd rorforbindelse
US7493960B2 (en) * 2005-09-20 2009-02-24 Schlumberger Technology Corporation Apparatus and method to connect two parts without rotation
WO2008002534A1 (fr) * 2006-06-27 2008-01-03 Vortexx Research And Development Llc Sous-appareil de déblocage de train de tiges et son procédé de fabrication
GB2457334B8 (en) 2006-08-21 2012-09-12 Weatherford Lamb Releasing and recovering tool
GB0805719D0 (en) * 2008-03-29 2008-04-30 Petrowell Ltd Improved tubing section coupling
US7779935B2 (en) * 2008-06-09 2010-08-24 National Oilwell Varco, L.P. Mechanically engaged and releasable connection system
GB2468271B (en) 2008-11-28 2013-06-19 Intelligent Drilling Tools Ltd Disconnect device for downhole assembly
US8322432B2 (en) * 2009-01-15 2012-12-04 Weatherford/Lamb, Inc. Subsea internal riser rotating control device system and method
US9127521B2 (en) * 2009-02-24 2015-09-08 Schlumberger Technology Corporation Downhole tool actuation having a seat with a fluid by-pass
US8469106B2 (en) * 2010-07-26 2013-06-25 Schlumberger Technology Corporation Downhole displacement based actuator
US20140034332A1 (en) * 2012-08-02 2014-02-06 Jerry Allamon Workstring Disconnect Tool and Method of Use

Also Published As

Publication number Publication date
WO2012118851A3 (fr) 2012-11-22
EP2681405A4 (fr) 2017-08-02
CA2894001C (fr) 2020-03-10
US20120152521A1 (en) 2012-06-21
US20170081932A1 (en) 2017-03-23
CA2828486A1 (fr) 2012-09-07
EP2681405A2 (fr) 2014-01-08
CA2828486C (fr) 2015-09-29
US9512683B2 (en) 2016-12-06
CA2894001A1 (fr) 2012-09-07
US11072985B2 (en) 2021-07-27
EP2681405B1 (fr) 2018-11-28

Similar Documents

Publication Publication Date Title
CA2828486C (fr) Ensemble de separation pour elements cylindriques
US10132125B2 (en) Resettable downhole torque limiter and related methods of use
US9267338B1 (en) In-well disconnect tool
US8453729B2 (en) Hydraulic setting assembly
US11519233B2 (en) Valve assembly
US20050155770A1 (en) System for Connecting Downhole Tools
EP3354842B1 (fr) Bouchon de sécurité de robinet à tournant sphérique
AU2022201659B2 (en) A rotating control device
US10941620B2 (en) Downhole swivel sub and method for releasing a stuck object in a wellbore
GB2341623A (en) Overshot tool
EP2122119A2 (fr) Outil de communication et procédé pour soupape de sécurité de sub-surface ayant un composant de communication
US8561692B1 (en) Downhole safety joint
US11473374B2 (en) Deployment tool and deployment tool assembly
EP2955318A1 (fr) Raccord à pivot de fond de trou et procédé pour libérer un objet coincé dans un puits de forage
CA2609184C (fr) Systeme expansible de suspension de colonne perdue et procede correspondant

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12751793

Country of ref document: EP

Kind code of ref document: A2

ENP Entry into the national phase

Ref document number: 2828486

Country of ref document: CA

NENP Non-entry into the national phase

Ref country code: DE

WWE Wipo information: entry into national phase

Ref document number: 2012751793

Country of ref document: EP